Project Period: 2018–2022
Researchers: Prasanna Krishnamurthy, Luca Trevisan, Tip Meckel and David DiCarlo
Seeing the fine details of what goes on half a mile beneath the Earth’s surface can be difficult. But by recreating subsurface geologic conditions in the lab, GCCC researchers have begun to understand how different rock attributes can affect fluid flow.
GCCC Ph.D. candidate Prasanna Krishnamurthy of the Petroleum and Geosystems Engineering Department has spearheaded a novel approach to visually and numerically analyze fluid flow. By programming the way that glass beads (sand) is fed into a glass chamber, crossbedding and ripple-like deposits can be manufactured with high precision. Experimenting with these fabricated sand packs that mimic natural sedimentary features found within reservoir rocks, GCCC researchers were able to see and measure how a fluid reacts to a rock’s porosity, permeability, and bedding pattern.
In geologic carbon storage injection sites, when CO2 is injected, the pressurized supercritical fluid travels from the injection site to pore spaces in the surrounding reservoir rocks until a variety of forces or a rock seal (cap) layers stops its flow.
In the experimental setup, fluid migration experiments were conducted using heptane and glycerol + ultrapure water, which mimic many of the attributes (like density and viscosity contrasts and interfacial tension) of supercritical CO2 and brine water in a real storage reservoir. At room temperature, humidity, and pressure, the experiment starts with the CO2 analogue, heptane, being injected into the bottom of the glass chamber by a pump.
The low flow rates ensure that the fluid is driven mainly by the upward force of buoyancy. The fluid travels upwards through the pores in between the beads until it reaches the bottom of the next layer of beads, continuing with some lateral migration, trapping and backfilling, until the fluid reaches the top of the chamber.
Back lighting and image processing are used to visually capture the process as well as calibrate and quantify the trapped fluid saturation during the experiment.
By observing the behavior of a CO2 analogue in the lab, scientists will be better able to predict the behavior of supercritical CO2 according to different attributes of reservoir rocks before any is injected underground—whether and how far it will move laterally and vertically—is helpful in understanding what sedimentary features within a potential reservoir will maximize the amount and success of CO2 storage.
Quantitative results are still under way.
We expect that we will be able to predict 2D tank saturation and flow times when given basic geologic characterizations such as grain size contract and fabric. Based on the matching of the numerical simulations to the sand pack chamber models, we anticipate that 3D simulations of fluid flow within more realistic complex systems are possible.
View a more technical summary of the work here.
The automated packing system
The experimental setup
Last updated: December 10, 2018